The remote control of sub-sea valve actuators for Christmas Trees (XTs) and manifold systems have evolved from simple concepts in the seventies to extensive and complex electro-hydraulic systems with offset distance capacity currently passing the 160 km limit. Traditionally hydraulic control power is generated at a host facility, based on a floating or semi-submerged unit or land based, and transmitted to the sub-sea facility at two different pressures: typically at 207 bars for the XT actuators, and pressures up to (and exceeding) 700 bars for the down hole safety valves (DHSV). Sub-sea hydraulic power units (HPU) located at the sub-sea production facility has been considered many times, but only a few and relatively insignificant installations of this type were ever made.
Process control systems are characterized by infrequent actuation and corresponding low average hydraulic power consumption, thus by means of accumulators located at the sub-sea facility it has been possible to use small bore tubing (typically ⅜″ to ¾″ tubing size) for the hydraulic power transmission. It has only exceptionally and infrequently been considered beneficial to deviate from this design practice as even a minor loss in reliability of the control system can be of great significance to cash flow and intervention efforts.
For most sub-sea process control systems, internal leakage from directional control valves (DCV) has been the dominant source of fluid consumption while actuation of the valves often accounts for less than 15% of the total fluid consumption.
Two courses of development initiates a revision of the current design practice:                Offsets up to 600 km are seriously considered for sub-sea tieback to the beach, essentially for transfer of dry gas products;        New processing facilities, especially fast acting process control valves, require high power levels on a near continuous basis.        
Sub-sea hydraulic control valves are typically configured in one of two major categories, i.e. open loop and closed loop, the former based on dumping used fluid to sea and the latter based on returning the used fluid to the host HPU for re-use. Recent installations in environmentally sensitive areas have demonstrated the undesirable feature of open loop systems, since both corrosion inhibitor substances and dye additives are difficult to achieve in Green environmental (environment-friendly) class and tend to be offered in Yellow class, or even Red class.
Hydraulic control systems being part of the sub-sea production control use either water based fluids (mostly a mixture of distilled water and glycol plus additives) or mineral based/synthetic fluids. For extreme offset distances, the inherently low viscosity of the water based fluids and corresponding moderate transmission losses tend to dominate. Water based fluids can be used in both open loop systems and closed loop systems, whereas mineral oil can not be discharged to the environment.
In order to provide the required power for high flow or long offset scenarios, by means of an economically justifiable umbilical (and one that can be laid full length in a single campaign), the power transmission has to be electrical, otherwise umbilical content will grow out of all reasonable proportions.
Traditionally the following objections have been raised against the few sub-sea HPU and thus locally closed hydraulic loop concepts proposed:                1. Leakage of process gas from the production tubing will migrate into the hydraulic control line to the DHSVs and from there contaminate the entire hydraulic control system, any attempt at boosting a fluid contaminated with gas by means of a pump intended for single phase operation would be futile (compressibility and possibly eventually even free gas phase);        2. Leakage of minor quantities of fluid to the environment will eventually deplete the local HPU reservoir and constitute an operational problem;        3. Wet make/break electrical connectors are unreliable;        4. Electrical squirrel cage motors are unreliable as used in a sub-sea environment;        5. Fixed displacement pumps have limited operating time, typically maximum 12 000 hours under ideal conditions of clean fluid and good lubrication, and will require frequent interventions and thus loss of regularity in operation;        6. Rotor-dynamic pumps, e.g. centrifugal pumps, typically provide low pressure and high flow, the opposite of what is required for an HPU intended for production control purposes.        
Thirty years of sub-sea oil and gas field developments and operations have basically demonstrated validity of these objections. However, recent developments have brought about many changes, the sum of which requires revision of the overall conclusion that sub-sea HPUs have no place in commercial sub-sea developments. With reference to the objections referred above the following changes have taken place:                1. DHSV actuators have improved considerably with respect to leakage. Nevertheless, leakage cannot be ignored as a factor, and the objection remains valid. A viable system requires system features to handle minor leakages of gas from the DHSVs;        2. A control system of absolutely no external leakage is unlikely, although environmentally significant leakages are rare. Replacement of lost fluid is required for high regularity operation;        3. Wet make/break connectors for 12 kV have been in operation for some time with good results and 36 kV systems have been qualified. High voltage (HV) wet make/break connectors have become a commercially viable component;        4. Electrical squirrel cage motors have been in operation for some time for 2 MW systems and 9-10 kV stator voltage. The motor issue is eliminated from the HPU discussion, which requires typically <15 kW of power for most applications;        5. Fixed displacement pumps for 2 MW power are being developed, but for less pressure than required for an HPU for control purposes;        6. Rotor-dynamic pumps for unprocessed well fluids (multiphase), produced water and even sea water, have been qualified for ratings up to 2 MW and operated for extended periods of time on fluids with significant particulate contamination.        
Thus it may be fairly stated that with state-of-the-art components related to a sub-sea HPU the gas leakage and the pump unit remain as the only issues in relation to achievement of a reliable sub-sea HPU for control purposes.
All electric control systems have been proposed and developed for production control and are under development for XT actuators and fast acting Production control valves (PCVs). However, there are major objections to all-electric control systems that will most likely slow down their introduction into the market place:                1. An electro-hydraulic actuator design for fail close operation is relatively complex and reliability will be an issue;        2. There are few, if any, convincing design for a fail close actuator for the DHSVs;        3. In the event that horizontal XT design is pursued, the XT cannot be retrieved without prior retrieval of the tubing, a major workover operation of high cost, both in rig cost and deferred production, thus focusing even more on reliability.        